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Coterra Energy Inc
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Good morning, and welcome to the Cabot Oil & Gas Second Quarter 2020 Earnings Conference Call. All participants will be in a listen-only mode [Operator Instructions] Please note this event is being recorded.
At this time, I'd like to turn the conference over to Dan Dinges, Chairman, President and Chief Executive Officer. Please go ahead.
Thank you, Allison, and good morning to all. Thank you for joining us today for Cabot's Second Quarter 2020 Earnings Call.
As a reminder, on this call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided in yesterday’s earnings release.
Despite the ongoing global pandemics impact on natural gas demand during the second quarter, which contributed to the lowest average quarterly NYMEX price since the third quarter of 1995, Cabot was still able to generate positive net income of $30.4 million or $0.08 per share. These results demonstrate our uniquely advantaged low-cost structure that we have continued to improve upon year-after-year, allowing us to deliver profitability and positive returns on capital even the very trough of the natural gas price cycle, which is where we believe we are today.
While we are seeing green shoots emerging in the natural gas market, which I will get into in more detail later in the call. I want to commend our team for delivering another profitable quarter in the face of the recent headwinds across our industry. Operationally, our team delivered another strong quarter with our daily production of 2.229 Bcf per day, exceeding the high end of our guidance range.
Our realized prices before the impact of derivatives, represents a $0.30 differential to NYMEX, which is in line with the low end of our full year guidance range and is a significant improvement relative to a $0.44 differential in the prior year comparable period.
Additionally, all of our operating expenses were in line with or below our guidance ranges for the quarter, demonstrating our continued focus on cost control. In the second quarter, we generated our first quarterly free cash flow deficit since the second quarter of 2018, but it's the only our second free cash flow deficit in the last 17 quarters, given the historically low natural gas price environment during the first half of this year, in addition to the combination of our first half weighted capital program and a second half weighted production profile.
Our plan for 2020 was expected to generate a slight free cash flow deficit during the first six months of the year before turning to a free cash flow positive program in the second half of the year. Ultimately, at the current strip, we still expect our capital program for the year to be fully funded within cash flow and to generate enough free cash flow to cover the majority of our regular dividend.
Our balance sheet remains exceptionally strong with a net debt to trailing 12 months EBITDAX ratio of 1.2 times at the end of the quarter. Subsequent to the quarter-end, we use cash on the balance sheet to repay our $87 million tranche of senior notes, which matured this month.
It is important to note that while we have seen a moderate expansion in our leverage metrics this year as a result of trough natural gas prices, we anticipate a significant compression in our leverage ratio next year at the current strip. This compression is driven, not only by the expectation for higher EBITDAX resulting from improved price realizations, but also from lower absolute debt levels as we continue to pay down our near-term maturities with free cash flow.
In yesterday's release, we reaffirmed our full year production guidance range of 2.35 to 2.375 Bcf per day, with the midpoint of the range implying a flat production levels year-over-year.
Additionally, we have reaffirmed our capital program of $575 million. We also initiated our third quarter production guidance range of 2.4 to 2.45 Bcf per day, which represents a 9% sequential increase in daily production. Midpoint of our guidance range for the third quarter and full year imply that production volumes in the fourth quarter will be roughly flat to the fourth quarter of last year.
On the capital side, we expect spending to sequentially decline in both the third and fourth quarters, driven by a reduction in our completion activity during the second half of the year. The macro outlook for natural gas markets is, obviously, top of everyone, so mind, especially given the stark contrast between the current market conditions and where we believe these dynamics could be during the winter withdrawal season.
On the demand side, while LNG exports have continued to disappoint this summer, we believe that July and August will likely mark the trough for the export levels, resulting in a gradual improvement in LNG utilization rates beginning in the latter part of the third quarter as the U.S. experiences fewer cargo cancellations.
Our base case expectation is that as we move into the winter, higher global gas prices will put U.S. LNG back in the money, leading to significant improvements in utilization rates and a corresponding increase in export related demand for natural gas, while we anticipate some reduction in power burn this winter due to reduced coal-to-gas switching, we would expect stronger residential and commercial demand year-over-year, assuming normal weather, which should offset any power-related demand loss.
On the supply side, we continue to see the potential for over 6 Bcf per day reduction in production year-over-year this winter, driven only – driven not only by the sizable activity cuts in natural gas focused basins, which we think is good, but also from steeper-to-cuts and oil-focused basins, resulting in the expectation for continued structural declines in associated gas production.
Given the ongoing focus across industry production on capital discipline, including the prioritization of capital allocation on debt reduction and return of capital to shareholders over growth, we believe any future recovery in natural gas supply will be much slower than in prior cycles. And ultimately, the market will need to see higher prices to either incentivize more production or to disincentivize LNG exports and economic coal-to-gas switching.
While there are certainly risks to this thesis, we remain cautiously optimistic about the natural gas market heading into this winter. We remain acutely focused on executing on a risk management strategy for 2021 that optimistically locks in hedges to protect against potential downside risk, while also remaining exposed to potentially one of the most favorable setups, we have seen for the commodity in years.
While we have yet to formulate official plans for 2021, in our release yesterday, we highlighted that based on 2021 NYMEX price assumptions of $2.75 per Mmbtu, which is roughly in line with the future – current futures. We can deliver similar production levels as 2021 from a modestly lower capital program, while delivering a free cash flow yield of approximately 8% and a return on capital employed between 19% and 20%. As we disclosed previously, every $0.10 improvement in NYMEX natural gas price is expected to increase our 2021 free cash flow by approximately $55 million, highlighting the upside potential, if the natural gas market does, in fact, reach a point of inflection this winter.
As we anticipate, a significant expansion in free cash flow in 2021, we remain committed to disciplined capital allocation with a focus on balancing the deployment of our free cash flow next year between returning capital to shareholders, and repayment of our $188 million of senior notes maturing in 2021.
Our capital return focus will be grounded in our base quarterly dividend of $0.10 per share or $0.40 annually and further supplemented by optimistic returns of capital, including special dividends and/or share repurchases.
While 2020 may ultimately deliver the lowest average NYMEX price on record since 1995, I am proud of Cabot's resiliency, highlighted by our ability to deliver positive free cash flow and positive corporate returns, while maintaining a strong balance sheet even in the trough of the commodity price cycle.
We will continue to execute, deliver on our plans for this year, which was formalized in February before the widespread impacts of the Global Pandemic, and we remain optimistic about the potential for an inflection potential in natural gas markets this winter and the corresponding expansion in our free cash flow, return on capital employed and return of capital to shareholders in 2021.
And Allison, with that comment, I will be more than happy to answer any questions.
We will now begin the question-and-answer session. [Operator Instructions] Our first question today will come from Arun Jayaram of JPMorgan Chase. Please go ahead.
Yeah. Good morning, Dan. I was wondering, if you could give us a little bit more color around your thoughts on modestly lower CapEx for 2021 Maybe give us a little bit of thoughts on that.
Well, we have indicated that our 2020 program was front-loaded, the remainder of 2020, we're not going to spend as much capital. We're also in the midst of negotiations with rigs and frack crews and looking at the efficiencies we've developed in our program operationally and what we're seeing and what we think will occur with our execution contracts in the 2021 program. We think we will see that modest reduction in that program.
Great.
Yes, if you wanted a ballpark 5% to 10% as a number right now might be a useful number.
Got it. So, something maybe in this 540 type range, something like that?
Yes, that would see that would seem reasonable.
Got it. I did want to maybe see if you could elaborate on called some of the outlook comments on 2021 obviously assuming a $275 million strip, you cited an 8% free cash flow yield, which would suggest on our math, call it $580 million in free cash flow, your annual dividends about $160 million. I think there's a desire of the company to return at least 50% of free cash flow to shareholders.
So, that would suggest maybe another $130 million, but just maybe want to get your thoughts on, let's assume $275 million is a good number next year, what kind of magnitude of cash return could we see to shareholders above your dividend again which is around $160 million a year?
Yes, we have -- I think we've set a pretty good clear track record of what our desire is and that is to return. As we couched 50% of our free cash flow back to shareholders, we have our debt we're going to take care of next year, we have the dividend also.
And some of our decision, and what we elect to do, we would -- if I'm speculating here a little bit. But we would probably maintain our dividend where it is. We'll talk about it throughout the year and we'll look at the macro market as we look out forward. But we've also have talked internally about special dividends, and we haven't changed off of our position to return cash to shareholders.
Great. Thanks a lot, Dan.
You bet.
Next question will come from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Good morning, Dan.
Good morning Jeff.
I want to ask for a little help on two ideas from the press release together first cabinet said that it can maintain the flattish production in 2021 with lower spend, we just discussed that. And then, as with your preamble, there was the note that improving demand and diminishing supply implied tailwinds for nat gas pricing in 2021, one view seems quite conservative and the other one is more bullish, so I was wondering how do we put these two contrasting views together to think about what may be more probable or less probable for Cabot in 2021?
Well, it's still early. We've -- as you read, or typically, as we do, we released in February what our outlook on 2021 is going to be. We have the advantage at that point-in-time to be able to see what the winter has done, look at what the strip is at that particular time, and we'll forecast then a much clearer definition of what our 2021 CapEx will be and what we're -- how we're going to set our expectations.
When we look at the market and at this time, we are conservative by nature, we have a -- what I think is a great setup for our shareholders to deliver a great deal of free cash flow. We'll deliver that free cash flow to our shareholders versus the banks. And I think that is going to be attractive. And we have a conservative program, which hopefully, it turns into that conservative program with the commodity price expectation we've stated, plus or minus $275 million. And we're comfortable with that right now.
If we see continued discipline in the market, and we see continued increases in demand. The LNG market comes back strong, we do have the ability to increase our program, but we're comfortable right now messaging that our lower CapEx program in 2021 is going to deliver the same volumes.
And just to follow that up real quick. And I don't want to put words in your mouth, but it sounds like what you're saying is we've got a conservative program set up there is already going to generate attractive free cash. And if the market goes our way and we get better pricing, first and foremost, we're going to make even more free cash. And then maybe at some point, depending on signals, we might increase the activity as a follow-on. Is that fair, or am I reading too much into it?
I wish I could have said it as well as you did, Jeffrey.
Okay, great. And I'll ask a follow-up. Just a lot more specific, I just want to get your view on the cancellation of the Atlantic Coast pipeline, the likely completion of the Mountain View pipeline. And how you see that affecting the nat gas market in 2021, both macro and maybe on Appalachian basis as well? Thank you.
Thank you, Jeffrey. And Jeff Hutton is on the edge of his seat.
Good morning, Jeffrey. There's a lot to take in with the -- project. But in the grand scheme of things on pipeline development, and also on specific, we always felt like that project was fairly long, because of the 600-mile, how many states they went through, et cetera, et cetera. And quite frankly, the high cost of that project, but also that project lands. It does tie in the trans for down to Station 165. We felt like that's quite a bit of gas we go into that market, obviously, there were some shippers that were optimistic that they'd be able to develop some more gas-fired generation down there.
I still think that's the case. But I think there's also ample supply on the transport system to satisfy that demand. So initially, and even today, we still think that there was too much gas in that region. We were somewhat concerned that it would saturate the market to the point that it would bleed upstream into the D.C. area where we're actively marketing gas. And so, quite frankly, the cancellation of that project gives us a more of an optimistic view on pricing for that region.
Okay, great. That's very helpful. Thank you. And by the way, we'll see you next week.
Very good.
Our next question today is from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian.
I wanted to follow up on a couple of the points raised here earlier, first on that mechanism to return cash to shareholders. How are you thinking, you talked about the special dividend, but how are you thinking about more of a more codified variable dividend versus special dividend versus share repurchase when that time comes?
Yeah, we're socializing that now internally. Brian, we have not – we have not put a framework around a formulaic delivery of that special dividend or variable dividend. As you've seen in the past, we have as similar to our buybacks. We've made those decisions when we feel comfortable about the market. We see the near-term support in the market that allows us to generate out in front of us, x amount of incremental free cash. So we're comfortable delivering certain portion of that and in some cases all of it back to shareholders. So, you know, I'm sorry I'm not specific on the formula but we have not – we have not gotten to that formula internally.
Understood. Thank you. And then my follow up is with regards to in-basin gas demand, can you give us the latest on what your expectations are for that market and how that also sets your view more broadly on what the outlook is for U.S. domestic gas demand, particularly from the power and industrial sectors?
Yeah, I'm going to make a comment then I want to turn it to Jeff, Brian, because it is an area that we are spending a great deal of time and focus on in-basin demand projects, but one of the – one of the most recent impetus, and it and catalysts that is, I think, driving now more attention to Northeast PA, as a location for demand projects has been the agreement of tax credits that Pennsylvania will allocate to at least four projects that bring a large manufacturing or natural gas demand project to state and spend x amount of money, employ x amount of people, then they would receive hundreds of millions of dollars over the next 10 years of tax credits.
That is a tremendous opportunity is out there and now in the books with the governor's signature. And we have had discussions with in-basin demand projects, and we have had for a while, a business development group that is working this opportunity for us. We like the idea of in-basin projects. We can look that up on the tailgate of our gathering system. And it is an incremental realizations to Cabot.
I'll let Jeff talk a little bit about his thoughts in this regard.
Hey good morning Brian. The -- just a quick recap. In-basin demand in the Northeast corner, PA has picked up quite a bit of load over the last four, five years, somewhere in the neighborhood of 1.5 Bcf a day of new demand.
And as you spread and look across the entire State of Pennsylvania, a lot of projects that are being built or have been built that are utilizing natural gas from the Pennsylvania area. So, it's all good, whether or not it's a Cabot-linked project or with others.
But specifically, we've talked about this in the past, where we've identified a number of sites and locations with different acreage and terrain sizes with water, with rail, with power and obviously, with our gas supply. And we continue to talk to industries that are located in the Northeast, already have markets in the Northeast.
There's been some new technology developed for some very unique projects that are good year-round loads and so nothing to announce today. Obviously, we have a huge amount of a huge amount of activity with different manufacturing associations and associations throughout that region, including local and county market development people.
So, it's an ongoing process. We found some -- we have some ideas that we're working toward, nothing definitive, but we're really happy with 0.5 Bcf a day low that we currently have up there. And most of those deals, of course, are long-term in duration because of the nature of their locations.
Great. Thank you.
Thanks Brian.
Our next question will come from Leo Mariani of KeyBanc. Please go ahead.
Hey guys. I was hoping to follow-up a little bit more on the kind of risk management/hedging strategy. As we sit here today, I mean it looks like futures curve in 2021 is offering a little bit north of 265, which seems like a very robust price compared to where we sit today and certainly one where I think Cabot's economics would be outstanding.
Why not try to maybe put some kind of call or structure in place to protect some of that downside at this point. Certainly, recognize your bullish view on macro. But as you guys know, you're always kind of a warm winter away from potential challenges in the gas market. So, any thoughts you kind of have on that would be great.
We have certainly a discussion regularly internally with our hedge committee and the price we see out there in 2021 is actually north of the $265 million that we see today. It is our intent to mitigate, as you say, the downside of the macro market. We have all been disappointed in the past, more so disappointed in the recent past than pleasantly surprised. We do think that there are some fundamental points that we made in my remarks that are constructive to a supportive underpinning of the market. And, yes, it can go down, and as I mentioned that the risk of that type of downside, we're fully aware of.
We think our program would deliver very well at $265 million. It is our intent to participate in the 2021 financial hedge market. And we'll do that appropriately with the vehicles, once we make the decision amongst the committee to do that. So we're thinking you like, Leo, we're pleased with where the market is right now. And we are, again, looking forward to participate in the hedge market. I can't tell you when, in advance, we plan to do something, but we do look at it every day.
Okay. That's great color. I just wanted to follow-up on your comments regarding 2021. I know it's not guidance and just sort of an outlook. But, I guess, flattish year-over-year production next year on my math, kind of, implies around a 4% decline versus fourth quarter 2020 levels. I know you guys certainly said that you think about this in a conservative way.
I guess would that end up being a similar shape to what we saw in 2020, where your production was down a little bit early in the year due to lack of winter fracking and then maybe pick up from there? Just trying to understand the dynamic as to why you'd kind of be down versus 4Q if gas is strong next year.
Yeah. We're – that's fairly granular to be able to give you the cadence quarter-to-quarter right now, Leo, I'm sorry. But, overall, right now, I'm comfortable just with our outlook being what it is, and it's flat with lower capital in 2021 and the cadence, we do try to manage the cadence, and it's a result of just a number of different things, the size pads we have, some of the winter season, the expectations on how the market is going to -- the macro market is going to look. We have not nailed down exactly the cadence for the quarters.
One thing I would say that, right now, if you look out in this summer, we had $1.60 gas, $1.70 gas in the, say, the April to October. And if you look out in 2021, if we're even partially right about the lower supply higher demand running through this winter, then you ought to be able to look out at the period between the April and October and say that, that market right now might be about a $2.60 market. So there is an effect, almost $1 difference during that period of time. So the cadence is still – we still have a discussion going internally. But those are some of the things that we look at.
Okay. That’s great color. Thank you.
Our next question will come from Charles Meade of Johnson Rice. Please go ahead.
Good morning, Dan to you and your team there.
Hello, Charles.
Hey, Dan, I wanted to – this isn't something you guys really made a point this quarter, but I wondered if you could give us an update on the evolution of your – of the Upper Marcellus in your views. And I think the last time you guys really dove into it, we were talking about EURs that were about 90% of what the Lower Marcellus is. And so I'm wondering if you could just give us an update on if that view has evolved anymore. And if you're – if you have any plans for iterating on that zone or doing some more extensive testing in that zone, either in the back half of this year or in 2021?
Yes. And we have drilled some upper wells this year. The number though, Charles, for comparison between the lower is more 70-plus percent EUR, not 90%. And that's in our.
Always been the case.
Yes, that's been our material, and that's always been the case. But the wells that we have drilled this year, and we've actually drilled uppers on three different pads and the wells in different locations in the field. And collectively, I'm not going to get grainier on it because couple wells have been on longer than the other wells that have come on more recently. But collectively, what we have seen is that our type curve on the upper is running slightly above, collectively, the type curve that we're using as our risk tight curve out there in the – in the field for the upper. You want to say, Steve?
Yes. So basically, what Dan's saying is that when you look at those pads currently, they've been on for a short period of time, but they're outperforming our projection for what the type curve would be for in that area. So we're very pleased with those results.
Yes. Got it. That's the kind of color I was looking for. I guess I was misremembered and miscalibrated on that, but thank you for taking me out. Dan, I recognize that maybe this is a bit of a long shot, but is there anything – any comments you would – you'd care to make about the case that the Pennsylvania AG uncorked earlier this year with you guys?
Well, the AG as a number of companies have now been recognized by the AG and through their investigations. As you are aware that the charges are, of course, disputed matters but nonetheless, Cabot is cooperating with the AG, and we're – they have provided his staff with facts and data addressing the allegations directly.
We are certainly telling Cabot's side of the story. It's undisputed up there that natural gas is naturally occurring in all the areas of Northeast Pennsylvania. And methane was up there in the rock prior -- but prior to the oil and gas industry ever going up there. When we moved up there, it was a greenfield operation, no drilling had taken place, no production. And there was natural gas in the water systems up there.
So we'll continue to work with AG, we're always employing our best practices to protect the environment and its operations and continue to be a leader in that regard. We do intend to be able to resolve this matter that is positive for all stakeholders.
Thanks for that color, Dan.
Thanks Charles.
Our next question today will come from Josh Silverstein of Wolfe Research. Please go ahead.
Yeah. Thanks. Good morning guys. Just follow-up on a question before about the upper and the lower Marcellus. You talked about two decades of inventory. I just wanted to see how you could split that right now between the upper versus the lower? And at what price deck that would be using?
On our drill cadence, if you look at how we've laid out our long-term program. And we have shown in a deck -- in the past, we've shown our production and drilling going out into the 2040 period. We have go out into the latter part of 2020 decade with our lower drilling. And then subsequent to that, we move into the upper Marcellus drilling. And we have that drilling out into the 2040 period.
Got it. So it's kind of 10 years for the lower lease right now, it’s kind of maintenance cadence?
It's slightly less, John, than 10 years, but it goes out towards the end of the 2020 decade, yeah.
Got you. Okay. And then maybe just talking about that maintenance cadence. One of the benefits of staying at this lower level and not growing that you can actually lower your base decline rate. I wanted to see where it was at the end of last year, where you think it might be at the end of this year? And if you were to just kind of hold things flat where that might be at the end of next year?
Yeah. We have -- our decline rate right now is 29% to 30%. And I don't have the number. And Steve Lindeman might be able to get me towards the cadence of our decline, as he's looked at our reserves towards the end of 2021.
: Right. So what – like Dan said, right now, we're kind of running in the 29% to 30% range. As you go out three or four years and add to the base, we'll probably be running in the 25% -- 24%, 25% range.
Got it. Understood. Thanks guys.
Our next question today will come from Kashy Harrison with Simmons. Please go ahead.
Good morning and thank you for taking my questions.
You bet.
So Dan, you highlighted 8% free cash flow yield in 2021 at $275 million. I was looking at your 2019 financials. It looks like you guys were able to do $1.35 billion of discretionary cash flow at about $260 million. I know that had about $150 million of hedge gains. But just given the simple math there would get you to about $1.2 billion. And then, if I took your – the implied CapEx that was discussed earlier in the call, it feels like we should be much higher than 8% at $2.75 million. And so I guess my question is, is that conservatism on your part, or should we be thinking about basis expansion or maybe cash income taxes as you look toward a higher-priced environment?
Yes. I'm going to pitch the ball to Matt.
Hey, Kashy, yeah, I think you nailed it – you nailed it with the cash tax piece. Obviously, last year, we also had the benefit of higher – significantly higher deferred tax add back, because of so that's tax reform, et cetera. So as we move forward now that we've maximized all the utilization of our NOLs and AMT, we're just not going to see those same tax benefits in the future. And I'd add, of course, there's always conservatism in our guide as well, as you know.
Got it. Very helpful. I guess this high-class problems. And then as you think about capital spending, as you look at your capital spending or, I was looking at your capital spending, it seems like you guys have spent just under 60% of the budget, but you've completed well over that proportion of your targeted wells for the year. And so I guess my follow-up question was, are you guys seeing some sort of – some efficiencies or cost improvements? And is there anything to read-through for implications to the full year budget, or is this just more so timing related?
We have in efficiencies in our program. We decided to maintain our $575 million CapEx. It's midyear right now. It might be a conservative position, but we wanted the least noise in the release as we could deliver, and we thought that was appropriate.
Got it. That's very helpful. And if I could just sneak one more in and just follow-up on some earlier questions on the Upper Marcellus. I was just wondering, I know we've always talked about the 70% of – the upper 70% of the lower on the well performance front. Have you guys ever talked about just how to think about the difference in well costs between the two zones?
Well, we haven't – we've talked about it maybe more indirectly, but we have made comments regarding our full development case of our Upper Marcellus. And to not make this a long-winded answer, Scott, has told me sometimes that I talked too long on my answers. But when you look at the full development of the Marcellus -- , you can really – Upper Marcellus, you can really look at the Upper Marcellus. It's a blank piece of paper for the most part. We intend to particularly with the legislation that has been passed recently about longer laterals and how you drill within or across units. It is our intent to lay out the sticks for the Upper Marcellus, with longer laterals on average than we've been able to drill in the Lower Marcellus program. With the drilling of the longer laterals, and I'm talking about kind of the 12,000 foot type laterals in the Upper Marcellus, there's efficiencies inherent in drilling longer laterals than longer laterals. With our currently, even in the Lower -- excuse me, even in the Lower, in our longer laterals, if we drill 11,000 or 12,000 foot laterals, and you look at our completion efficiencies or some represent their -- the cost of development in what the cost is per foot and our -- even in our Lower, we have a -- say, a $700 -- slightly over $700 per foot cost in our 11,000 foot type of lateral that we drill in the Lower and those as actually cost that we have in first and second quarter of this year.
There's another thing on the efficiencies that we see in those -- in that cost Cabot also loads in -- of our cost per foot. We also load in our -- all our facilities in that cost, and we load in all the construction associated with our pad sites into those costs. That is, again, all-in cost for us and the other thing we do is we have what we think are very efficient completions.
We have 2,500 pounds of proppant we use in our completions. And versus, I know some other companies might use less proppant. So, their cost for proppant is going to be maybe slightly less than ours, but we do like the amount of gas that we have coming in out of our wells and so our recipe, we think we have dialed in, is very efficient.
So, there is going to be, overall, considerably less cost attached to the development of our Upper Marcellus, including use of roads, reuse of pad sites. We hope reuse of some of the equipment, so we would take -- even though the -- it might be a 70%-plus comparison to the Lower, we think on a return profile basis because of what I'm just mentioning, our Upper development is going to be in an extremely good return profile.
That's excellent color. Thanks for all that.
Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference back over to Dan Dinges for any closing remarks.
Thank you, Allison. And once again, I would just like to say thanks again to those dedicated shareholders of Cabot, but also their gratitude to Cabot's team. They have been out there through this this very difficult environment. Many of our field operators have been going to work every single day even though some of the corporate headquarters and office in Pittsburgh have honored the stay-at-home because of this pandemic. But those guys and girls out there in the field have gotten up every day to head out and do the work.
And as you can see by our numbers, we've been able to deliver on our program and I'm very proud of the group. So, thanks again for the attention. Look forward to next quarter's call. Thank you.
The conference has now concluded. We thank you for attending today's presentation, and you may now disconnect your lines.